1. Field of the Invention
The prior art relates to petroleum wells in general and to drilling fluids in particular.
2. Prior Art
Drilling muds or drilling fluids are used in drilling operations such as in the drilling of petroleum wells. The drilling apparatus comprises in the most general terms, a length of drill stem (the drill string) often having a rotary drill at its downhole end. Drilling fluid or xe2x80x9cmudxe2x80x9d is pumped through the well bore.
Every drilling mud is comprised of a base fluid and some combination of dry and or liquid components that are mixed into the base fluid to create a mud that has the desired components in the desired ratios. Typically, such mixing is done in the field, and involves the labor of many people and numerous bags, tanks, pails, mixing hoppers, mixing pumps, and hoses.
There are two main types of drilling mud: oil based muds (OBM) and water based muds (WBM). As their names imply, the two types of muds can be differentiated by the nature of their base fluids. Fresh or salt water makes up the base fluid in WBM""s while diesel oil, mineral oils, or synthetic oils often serve as the base fluid for OBM""s, although salt water is often emulsified into the base fluid with primary and secondary emulsifiers in OBM""s.
The drilling mud must accomplish several tasks. One of the primary purposes of the drilling mud is lubrication. The drilling mud lubricates the drill bit, helping to prevent damage to the bit as it grinds through the earth. The drilling mud also lubricates the drill stem, preventing it from sticking to the walls of the well bore as it is rotated. Additionally, the drilling mud cools the bit and string, dissipating the heat generated by the drilling itself and the geothermal heat, where present.
As the drill bit rotates, it dislodges pieces of rock, clay, dirt, and etc, known as cuttings. Additionally, portions of the well bore may cave off from time to time. While such cavings are to be avoided, if possible, both the cavings and the cuttings must be removed. This is another function of the drilling fluid. As drilling mud is pumped through the well bore it picks up and carries these drill cuttings and cavings out of the well bore. Additionally, the drilling mud should be capable of suspending the cuttings in the drilling mud when circulation is stopped. If the drilling mud does not have enough gel strength to keep the cuttings in suspension, they will settle out of the drilling mud.
If the cuttings settle out of the drilling mud, they can collect in cutting bedsxe2x80x94piles of cuttings and cavings that have collected at one point in the well bore. However, in directional drilling, the well bore can have one or more sections that are between horizontal and vertical. The low sides of these sections of the well bore are particularly susceptible to the formation of cutting beds, particularly in bends where the bore moves from a more vertical section to a more horizontal section. Cutting beds in these positions can bind the drill stem. This can impede rotation of the stem and impede steerage of the bit in directional drilling. Cutting beds can also impede the insertion of additional drill stem or the removal of drill stem that is already in place. Similarly, cutting beds can cause the bit or other downhole tools to become stuck as well. Thus, it is important for a drilling mud to minimize the rate at which cuttings fall out of suspension when the circulation of the drilling mud stops.
Another requirement of the drilling mud is to help hold up the well bore walls. The drill bit necessarily cuts a hole in the earth that is slightly larger than the diameter of the drill stem. The drilling mud circulating in the well bore provides support to the well bore walls and prevents them from collapsing.
Instability in the well bore is an especially frequent problem in shale formations. Shales are complex clay rich geological sediments. Their notorious instability is believed to arise from the fact that some of the minerals responsible for cementing the shale components together are at least partially soluble in water. Adding water to these components will cause them to swell and dissolve, thereby reducing the forces holding the shale together and resulting in its deterioration. Conversely, drying the shale will increase the cementing effect the minerals have on the shale, causing the shale to harden and strengthen. The instability of a shale will vary directly in proportion to the amount of time spent in open hole operationxe2x80x94that is, the amount of time with no casing separating the drilling mud in the well bore from the formation.
One clay mineral that is especially problematic is sodium montmorillonite, also known as swelling bentonite. Sodium montmorillonite is especially problematic because it expands to several times its original volume when it encounters water. Thus, the water in a WBM pumped through shale formation can cause the sodium montmorillonite in the well bore wall to swell substantially. Such swelling can weaken the bond between the clay particles and the other components of the shale. This can cause the well bore wall to slough off or to collapse altogether. Additionally, the swelling of the clay particles can cause the well bore diameter to shrink, such that it may restrict the drill string or actually cause the drill string or any number of downhole tools to become stuck. Also, when the clay particles enter the drilling mud and swell, they can increase the drilling mud viscosity beyond desirable levels, which can increase the well bore pressure, making the mud more difficult to pump and simultaneously increasing stress on the well bore, leading to increased risk of well bore erosion or collapse and/or loss of drilling fluid to the surrounding formation through the well bore walls. Shales high in sodium montmorillonite, and thus especially susceptible to the foregoing problems, are commonly encountered in the Gulf of Mexico and the North Sea.
When well bores are expected to encounter shale formations, drillers will often use an OBM to reduce the exposure of the shale to water. However, the cost of using an OBM is significantly greater than WBM""s because of the cost of the base fluid. Additionally, OBM""s and their cuttings are subject to more rigorous environmental treatment than their WBM counterparts.
Another function of the drilling mud is counteracting the pressure of the formation. When petroleum reservoirs are encountered during drilling, they may be under significant pressure. These pressures will tend to assault the bore wall, potentially causing it to implode and also potentially forcing the petroleum product into the well bore. One way of addressing the problem is by increasing the density of the drilling mud. This will counter the pressurized formations encountered downhole, neutralize the pressure on the well bore wall, and prevent the petroleum products from escaping into the well bore.
The well bore may pass through many different types of soil, rock, shale and sand. Although some of these formations will be pressurized as discussed above, others will not be pressurized or will be under less pressure than the drilling mud. In such cases, a common and expensive problem is the loss of drilling mud to the formation. Although problematic in WBM""s and OBM""s these types of losses are particularly troublesome in OBM""s. However, with either mud type, the mud is lost in the same manner. Fractures or porous soil materials essentially act like leaks in the well bore, allowing the drilling mud to simply flow out of the bore. It is important to minimize such losses. To this end, the drilling mud is configured to deposit a thin filter cake on the walls of the well bore.
The filter cake is a thin layer of non-water permeable or semi-permeable material at the wall of the well bore. It seals fractures in the formation that open into the well bore and otherwise acts as a barrier between the well bore and the formation through which the well bore passes. To the extent that the formation is porous or otherwise capable of receiving fluids under pressure, the drilling fluid will run out of the well bore into the surrounding formation. However, as the drilling fluid runs out of the well bore, items that are not in solution will be carried with the drilling fluid to the well bore wall. Those items that are too large to pass through the pores of the formation will clog the pores and become caked to the well bore wall, forming the filter cake, which will inhibit further fluid flow out of the well bore. The water phase of the drilling fluid that is squeezed through the filter cake is called mud filtrate. The object of the filter cake is to minimize the amount of mud filtrate that escapes from the well bore.
Another problem that arises in low pressure formation is differential sticking. This occurs when the pressure of the drilling mud exceeds the pressure of the surrounding formation, and the resultant difference in pressure forces the drill stem against the well bore wall. The pressure exerted against the drill stem by the drilling mud can be sufficient to bind the drill stem, causing it to become stuck. The drilling mud should be configured to prevent or inhibit flow into such low pressure sands in order to prevent differential sticking as well as the accompanying mud loss.
The drill string is typically composed of dozens if not hundreds of sections of approximately thirty-one foot sections of steel pipe. The weight of such a length of pipe is significant. Another of the many purposes of the drilling mud is to help to support this weight, through its buoyancy.
Although there are many known drilling mud compositions that can achieve one or more of the foregoing requirements, obtaining such a drilling mud in the field can be difficult. Many drilling fluids additives must be transported in liquid form because of the hydroscopic nature of their ingredients. This takes up significant shipping space and makes handling the additives more difficult. Additionally, as mud engineers attempt to optimize a drilling mud to match the particular conditions encountered on site, they may consume a disproportionate amount of a particular mud component. Because of the remote locations where petroleum exploration is frequently conducted, shipping space is often at a premium. Thus, using an excess amount of a single component in an effort to match encountered conditions may cause the mud engineer to run short of that particular component. This can lead to expensive downtime while additional supplies of the component are sought. Therefore, a drilling fluid that meets the following objectives is desired.
It is an object of the invention to provide a drilling fluid that is capable of lubricating the drilling bit.
It is another object of the invention to provide a drilling fluid that is capable of coating, lubricating, and inhibiting the hydration of well bore cuttings.
It is another object of the invention to prevent the drill bit and stabilizers from balling up with up with clay or shale.
It is another object of the invention to provide a drilling fluid capable of carrying drill cuttings out of the well bore.
It is another object of the invention to provide a drilling fluid configured to reduce cutting bed build up during the drilling of deviated wells.
It is still another object of the invention to provide a drilling fluid capable of supporting the well bore walls.
It is still another object of the invention to provide a drilling fluid configured to minimize well bore erosion.
It is yet another object of the invention to provide a drilling fluid capable of substantially sealing the well bore.
It is still another object of the invention to provide a drilling fluid capable of substantially inhibiting the hydration of shale formations.
It is still another object of the invention to provide a drilling fluid capable of forming a thin, tough, lubricated filter cake on the well bore wall.
It is still another object of the invention to provide a drilling fluid configured to inhibit differential sticking of the drill string and of wire-line tools.
It is yet another object of the invention to provide a drilling fluid capable of being used to hydraulically drive a mud motor.
It is a still further object of the invention to provide a drilling fluid that may be easily transported to remote locations.
It is still another object of the invention to provide a drilling fluid that may be easily prepared on site.
It is yet another object of the invention to provide a drilling fluid whose components may be stored in a dry powder.
It is still another object of the invention to provide a drilling fluid whose components may be easily pelletized.
The invention comprises a drilling fluid or mud having several components, including leonardite (humic acid); potassium acetate; partially hydrolyzed polyacrylamide (PHPA); low viscosity polyanionic cellulose polymer (PAC); sulfonated asphalt; sulfoalkylated tannin; polyacrylate copolymer and/or maleic anhydride copolymer; micronized cellulose fiber; calcium carbonate; slaked lime; potassium carbonate; bentonite; and xanthan gum. These components are preferably premixed in a dry formulation, and shipped to the site in bags or bulk tanks. In one preferred embodiment, the leonardite, potassium acetate, PHPA, PAC and sulfonated asphalt may be mixed as one composite additive and the remaining ingredients mixed as a second additive.
This offers substantial advantages over the prior art in that the drilling mud of the present invention may be formed simply by adding a predetermined amount of the dry mix to water, and is thus much easier to make than the prior art wet mix drilling fluids. Mixing liquid components also typically requires multiple tanks, hoses, stands and connections, and close supervision during mixing. Moreover, spills frequently occur in mixing these prior art mud components. The components of many prior art liquid additives include oil based carriers. As a result, when they are spilled, a dangerous slip and fall condition is often created. No such condition is created by a spill of the dry components of the present invention.
Furthermore, because of the remoteness of many drilling sites, shipping can be a problem. Transporting the drilling fluid additives to the drilling site in a dry form will take up much less space both in transit and during storage on site, allowing the ingredients for a large amount of fluid to be brought in at once and stored on site through the duration of the project.
The foregoing advantages complement each other. As stated above, when liquid additives are used, on site personnel will make up the drilling fluid by combining preset ratios of several components, typically in large quantities using several tanks, hoses, and etc. Given the difficult conditions under which many wells are drilled, errors frequently arise in the mixing process, often resulting in excess quantifies of one or more components being spilled or added to the drilling mud mixture. This can lead to a premature consumption of one or more key ingredients and to the well site being effectively out of drilling fluid because one drilling fluid component has run out. Because the drilling operation cannot run without drilling fluid, drilling will effectively be stopped while more of the missing component is sought which, given the remoteness of some drill sites, can take a significant amount of time. Such delays can constitute a substantial expense, as many drilling rigs cost anywhere from several thousand to several hundred thousand dollars (U.S.) per day. Thus, having a dry mix drilling mud in which all or substantially all of the components are premixed and which can be prepared merely by adding a dry powder to water, will eliminate the possibility that the drilling mud will run out simply because one component has been prematurely consumed.
Additionally, the ability to transport the drilling mud in a dry form will make it easier to carry excess drilling fluid mix to a well site at the commencement of drilling, and thus to insure against running out of drilling fluid by keeping excess stock on hand. The volume of the individual liquid components, the limited shipping space, and the limited storage on many well sites made shipping excess drilling fluid to a site difficult with many prior art wet mix drilling fluids. The present invention will make it much easier to keep sufficient inventory on hand in order to guard against premature consumption of the drilling fluid.
The use of dry mix drilling fluid additives is complicated by the fact that several common drilling mud components, particularly PHPA and potassium acetate, are quite hydroscopic. When these components are included in a powder, the powder absorbs water from the atmosphere and forms clumps, solid blocks, or particularly in the case of potassium acetate and PHPA, soupy semi-liquids, after only a short exposure to the atmosphere. While such hydration can be avoided through careful storage practices, the conditions at most drilling sites makes this at least impractical, if not impossible. Consequently, many prior art drilling fluid additives have been provided in liquid form. By adding a hydration buffer to the mixture disclosed herein, the inventor has discovered that he can maintain the mixture in a flowable powder form, allowing him to achieve all of the advantages of a dry mix drilling fluid.